System for recovering natural gas liquid from low pressure source

ABSTRACT

A system (102; 302) for recovering natural gas liquid from a low pressure gas source (110; 310), comprising a gas/gas heat exchanger (104; 304), fluid from the gas source flowing therethrough; at least one separator (108; 308) for receiving the fluid from the gas/gas heat exchanger (104; 304) and separating liquid from the gas, the gas being directed via a connecting pipe (116; 316) to the gas/gas heat exchanger (104; 304) where it cools the fluid from the gas source; characterised in that the connecting pipe (116; 316) includes expansion means (106; 322) for cooling the gas therein and liquid injection means (120; 320) for saturating the gas with liquid.

FIELD OF INVENTION

The invention relates to a method for recovering natural gas liquid from a low pressure source.

BACKGROUND

A natural gas stream often contains light hydrocarbons. Natural gas liquids (NGL) is the general term for liquids extracted from the natural gas stream (ethane and heavier products) and within this liquefied petroleum gas (LPG) is the term used to refer to extracted liquids where the main components are propane, n-butane and iso-butane.

Removal of NGLs from natural gas is desirable for the following reasons:

-   -   Production of what is known as ‘pipeline quality’ dry natural         gas. Major transportation pipelines usually impose restrictions         on the make-up of the natural gas that is allowed into the         pipeline. That means that before the natural gas can be         transported it must be purified. Typically, this involves         meeting a dew-point specification of the gas pipeline and will         include the removal of C4+ components from the gas stream.     -   In cases, where the natural gas is burned as fuel gas or flared,         to meet fuel gas calorific valve/Wobbe index value, dew-point         specifications and to minimize CO₂ emissions (during flaring or         burning as fuel) it is desirable and/or essential for NGLs to be         removed from natural gas.     -   NGLs include ethane, propane, butane, iso-butane, and natural         gasoline, and can be very valuable by-products of natural gas         processing. These NGLs are sold separately and have a variety of         different uses; including enhancing oil recovery in oil wells,         providing raw materials for oil refineries or petrochemical         plants, and as sources of energy.

Depending on the requirement, hydrocarbon dew point control packages or cryogenic plants can be used to extract NGL from gas streams. Hydrocarbon dew point refers to the temperature at any pressure range or the pressure at any temperature range where hydrocarbons begin to condense from the gas mixture. At the same temperature, heavier hydrocarbons' dew point temperature increases as the pressure is reduced

There are various types of Hydrocarbon Dew Point Control (HCDPC) units available in the market to extract NGL (Natural Gas Liquid) from a natural gas stream (associated or non-associated gas). The following is a brief review of the methods used to reduce hydrocarbon dew point in gas streams. As these processes are well known, for the sake of brevity, process descriptions are not included as they are well covered in the literature:

1) Low Temperature Separation (LTS)

If the raw gas is at high pressure, the removal of hydrocarbons can be accomplished by refrigeration obtained through the expansion of gas by means of a Joule-Thomson (JT) valve. Injection of glycol is required to prevent the formation of hydrates. However, if the raw feed gas pressure is low, this will require booster compression for a JT valve system to be viable.

2) Turbo-Expander Dew Point

This process is a variation of the LTS process in which the energy pressure held in the gas is used to move an expander turbine, which in the isoentropic expansion generates refrigeration and exports mechanical work. This work is used to drive a compressor to partially restore the gas pressure. Here again, the raw feed gas pressure has to be relatively high to generate adequate chilling for NGL recovery.

3) Refrigeration

The most common method used for gas dew point control is mechanical refrigeration. This technology is suited especially when pressure is not available to be used to self-refrigerate the gas. Mechanical refrigeration system however are bulky and expensive which includes compression equipment and power consumption.

4) Adsorption

This method uses adsorbents like silica gel that have the capability to adsorb heavy hydrocarbons. The system is set up in multiple beds cycling in short operating cycles of adsorption, desorption, of approximately 20 minutes. This method was well used in the 60s and early 70s and was gradually abandoned. Recently, new adsorption materials are making this method economically attractive for certain project applications. However, these adsorbent again typically operate effectively with higher feed gas pressures with regeneration and recovery of NGLs being undertaken at lower pressure and higher temperatures.

5) Static Expansion Devices

The Vortex-Tube Device and the Supersonic Tube technology. For these devices also require high pressure gas for the system to generate adequate chilling of the gas stream for NGL extraction.

6) Membranes

Silicon rubber membranes, for example, have the ability to permeate heavy hydrocarbons rather than light. This makes them a potential candidate for dew point control. However, these systems require some amount of pre-treatment to protect the membranes and compression of the permeate stream to minimize NGL losses. In addition, to be economically viable, these systems require relatively high inlet gas pressures.

As can been seen from the preceding discussions, whilst there are many NGL recovery systems by means of various types of HCDPC units, these are only really suitable for feed gas streams that operate at relatively high pressures. In addition, the few, like refrigeration systems that can handle low pressure feed gas streams, are very bulky, complex and costly, making them economically not viable for many low pressure applications.

An aim of the invention therefore is to provide a system for recovering NGLs which operates effectively with a low pressure source of natural gas.

SUMMARY OF INVENTION

In an aspect of the invention, there is provided a system for recovering natural gas liquid from a gas source, comprising:

-   -   a gas/gas heat exchanger including a first inlet and first         outlet, fluid from the gas source flowing from the first inlet         to the first outlet;     -   at least one separator for receiving the fluid from the first         outlet of the gas/gas heat exchanger and separating liquid from         the gas, the gas being directed via a connecting pipe to the         gas/gas heat exchanger where it flows therethrough from a second         inlet to a second outlet for cooling the fluid flowing between         the first inlet and first outlet;     -   characterised in that the connecting pipe includes expansion         means for cooling the gas therein and liquid injection means for         saturating the gas with liquid.

Advantageously, cooling the gas after separation and injecting liquid thereinto to saturate the gas with evaporant allows the gas/gas heat exchanger to be much more effective at low gas source pressure.

In one embodiment the expansion means is a Joule-Thomson valve. In another embodiment the expansion means is a turbo expander. In yet another embodiment, the expansion means is a Static Expansion Device such as a Vortex-Tube Device or Supersonic Tube technology. Typically the expansion means reduces the pressure of the gas and as a result reduces the temperature thereof.

In one embodiment the liquid used to saturate the gas is water. However it will be appreciated that other liquids e.g. propane may be used as a suitable evaporant depending on the temperature and pressure conditions.

In one embodiment at least part of the water used to saturate the gas is derived from the separator and/or other downstream sources.

Typically the liquid injection means is downstream of the expansion means.

In one embodiment the liquid is injected downstream of the expansion means at a rate to enable the gas at the second outlet to be saturated. This maximizes evaporative cooling duty at the gas-gas heat exchanger.

Typically the liquid injection means is a sprayer for spraying the liquid into the gas as a mist.

In one embodiment a hydrate or ice inhibitor is mixed with the injection liquid to prevent freezing thereof. Typically the hydrate or ice inhibitor is methanol or Mono Ethylene Glycol (MEG).

In one embodiment liquid is injected in excess of the saturation amount to avoid solid deposition at the gas/gas heat exchanger. Advantageously the excess liquid ensures that total dissolved solids (TDS) content of the liquid phase does not exceed its saturation point, thereby helping to prevent precipitation of any of the TDS in the system.

In a conventional system the JT valve or other expansion means is upstream of the separator. When the gas source is at high pressure a large pressure drop can take place at the JT valve resulting in a large reduction in temperature. However, for low pressure gas sources only a small pressure drop can take place, so the reduction in temperature is smaller. Thus in a conventional system the heat exchanger is ineffective for low pressure gas sources.

However, in the present invention the JT valve or other expansion means is downstream of the separator, and liquid evaporant such as water is injected to increase the enthalpy of the cooling fluid, reducing the temperature thereof compared to a conventional system and making the heat exchanger effective even for low pressure gas sources.

In one embodiment the gas from the second outlet may be flared off.

In one embodiment the liquid from the separator comprises water and hydrocarbons (including NGL), which are directed to respective outlets for further treatment.

In one embodiment the system is effective at recovering NGL from gas sources at less than 20 barg (2.1 MPa), such as 10 barg (1.1 MPa) or 3 barg (400 kPA) or less. Typically the NGL recovery is 80% or more at 5 barg (600 kPa) compared to a conventional system at 50 barg (5.1 MPa; a conventional system at 5 barg (600 kPA) may only have NGL recovery of 1% or less compared to its operation at 50 barg (5.1 MPa)).

BRIEF DESCRIPTION OF DRAWINGS

It will be convenient to further describe the present invention with respect to the accompanying drawings that illustrate possible arrangements of the invention. Other arrangements of the invention are possible, and consequently the particularity of the accompanying drawings is not to be understood as superseding the generality of the preceding description of the invention.

FIG. 1 is a graph of water saturation against pressure at different temperatures.

FIG. 2 illustrates a conventional NGL recovery system

FIG. 3 illustrates an NGL recovery system according to an embodiment of the invention.

FIG. 4 is a graph of water saturation against pressure at different temperatures with respect to an embodiment of the current invention.

FIG. 5 is a graph of the gas phase envelopes at different separation points.

FIG. 6 is a graph of a phase envelope with a small amount of crude being spiked.

FIG. 7 is a graph of a phase envelope without crude being spiked.

FIG. 8 illustrates a conventional NGL recovery system using a turbo-expander

FIG. 9 illustrates an NGL recovery system according to a further embodiment of the invention.

DETAILED DESCRIPTION

Hydrocarbon Dew Point Control (HCDPC) of low pressure gas uses the concept of evaporative cooling, coupled with a gas expansion device which may either be a JT Valve, Static Expansion Devices or a Turbo-Expander, to chill the gas stream to condense and remove the heavier hydrocarbon components (NGLs) from the natural gas stream.

Evaporative cooling is the addition of water vapour into gas that is water dew pointed, which causes a lowering of the temperature of the gas. The energy needed to evaporate the water is taken from the gas in the form of sensible heat, which reduces the temperature of the gas, and converted into latent heat, the energy present in the water vapour component of the gas, whilst the gas remains at a constant enthalpy value. This conversion of sensible heat to latent heat is known as an adiabatic process because it occurs at a constant enthalpy value. Evaporative cooling therefore causes a drop in the temperature of gas proportional to the sensible heat drop and an increase in humidity (or water vapour content) of the gas proportional to the latent heat gain.

A simple example of natural evaporative cooling is perspiration, or sweat, secreted by the body, evaporation of which cools the body. The amount of heat transfer depends on the evaporation rate, however for each kilogram of water vaporized 2257 kJ of energy at 35° C. are transferred. The evaporation rate depends on the temperature and humidity of the air, which is why sweat accumulates more on humid days, as it does not evaporate fast enough.

The evaporative cooling medium as used in this invention is typically fresh (demineralized) water but may be any medium that achieves vaporization in the gas stream to convert sensible heat in the gas to latent heat of vaporization of the medium.

It is also noted that the description of the system as detailed in this document are mainly applicable for low pressure systems, where typically water is used as the evaporative medium, the concept as detailed here may also be used for high operating pressure systems with a suitable alternative evaporative medium.

In the case where water is used as an evaporative medium, this concept is particularly suited for low pressure gas stream which does not have enough upstream pressure to chill the gas on expansion through either a JT Valve, Static Expansion Devices or a Turbo-Expander (or a combination). It is noted that, typically on expansion of low pressure gas, the water dew point of the expanded (lower pressure) gas is significantly lowered. As illustrated in FIG. 1, this is because at low pressures, e.g. less than 20 barg (2.1 Mpa), the saturation water content of gas increases exponentially as the gas pressure is lowered (at constant temperature).

There are many facilities where natural gas is produced at low pressures of between 3 to 20 barg (400 kPa-2.1 Mpa) and these include:

-   -   Associated gas from oil and gas production facilities which         typically operate between 3 to 15 barg (400 kPa-1.6 Mpa) at the         inlet to the receiving facilities. In many cases, the associated         gas is an undesirable by-product that is utilized as fuel gas         with the balance flared, along with valuable NGLs as it is         uneconomical to extract.     -   NGLs are an excellent enhanced oil recovery (EOR) solvent.         However, the cost of extracting NGLs from low pressure         associated gas makes this option for EOR not viable in many         cases.     -   Non-associated gas production reservoirs in many cases are         abandoned when flowing pressures decline below 10 barg (1.1 MPa)         as it becomes uneconomical.     -   Low pressure off-gas from various sources like the refinery or         Petrochemicals Complex in many cases are either used as fuel gas         or flared. There is an increased demand to install NGL         extraction to recover valuable NGLs and in return send the clean         fuel gas for burning.     -   Vents from FPSOs, crude transportation tankers and storage tanks         are typically vented along with valuable NGLs that vaporize from         the crude stored in the tanks. Apart from the environmental         impact of venting, there is significant revenue loss due to         shrinkage of crude volumes due to these vaporization losses.

The installation of HCDPC units for NGL extraction from low pressure natural gas has both the economic and environmental benefits as the main polluting components from the off gas are separated and the value added products like lean natural gas and NGL are produced. The burning of methane rich gas produced from this unit without polluting and soot forming components is beneficial from an environmental point of view.

While it is noted that NGLs constitute a small fraction of natural gas from wells and various other sources, its contribution towards greenhouse gas emissions is significant when the gas is burnt as fuel gas or flared. Typically, CO₂ emissions can be reduced by approximately 30% with extraction of NGLs from the gas. It is more significant for low pressure natural gas as the vapour liquid equilibrium favours vaporization of heavy ends into the gas phase resulting in higher content of NGLs in the gas stream. Ironically though, it is the low pressure natural gas streams that are typically disposed as fuel gas or flared as is uneconomical to recover.

With regard to FIG. 2, a conventional hydrocarbon dew point control system is illustrated. This system is widely used but is not suitable for low pressure gas (typically below 20 barg (2.1 MPa)).

The conventional system 2 comprises a gas/gas heat exchanger 4, a JT valve 6, and a separator 8. Feed gas 10 at 5 barg (600 kPa) and 68.8° C. is passed through the heat exchanger where it is cooled to 58.8° C. at 4.8 barg (580 kPa). The gas is then passed through the JT valve where it is further cooled to 40.6° C. at 0.5 barg (150 kPa) into the separator where gas is separated from liquid. The liquid NGL and water components are directed to respective outlets 12, 14 for further processing. The gas is directed to a pipe 16 for use as a cooling fluid in the gas/gas heat exchanger 4, before being sent to a flare point 18.

As can be seen, minimum temperatures achievable with the conventional configuration, with feed gas pressure of 5 barg (600 kPa) and temperature of 68° C., is approximately 40.5° C. In addition, the Cold Separator being located downstream of the JT Valve, thus operating close to atmospheric pressure, will not result in significant NGL (condensate) recovery as indicated in the above example where only 0.4 bpd of NGLs is condensed at the Cold Separator.

As such the industry is striving for a new flexible, reliable and a safe process that can cost effectively extract NGLs from low pressure natural gas.

FIG. 3 illustrates an NGL recovery system 102 according to an embodiment of the invention which also comprises a gas/gas heat exchanger 104, and a separator 108, but where the JT valve 106 is located downstream of the separator 108, rather than upstream as per the conventional systems. In addition, a liquid injection system 120 is provided, preferably downstream of the JT valve, to increase the enthalpy of the cooling fluid, reducing the temperature thereof compared to a conventional system and making the heat exchanger effective even for low pressure gas sources 110. The separator provides gas, NGL and water to respective outlets 116, 112, 114 as hereinbefore described, and the water therefrom may be used as a water supply for the liquid injection means. The lean gas is directed towards the flare point 118.

In more detail:

-   -   Feed gas 110 from the upstream production facility is routed to         a Gas-Gas Exchanger 104. If temperatures are expected to drop         below hydrate formation or freezing temperatures and if the feed         gas is not dehydrated, a hydrate inhibitor or anti-freeze, like         methanol is injected into the feed gas stream to prevent         hydrates and/or icing of condensed water. The hot feed gas         stream is chilled by the cold gas stream from the JT-Valve 106.     -   The chilled feed gas stream is then routed to the Cold Separator         108 where 3 phase gas-oil-water separation is undertaken.     -   The separated gas is routed to the JT-Valve 106, the oil phase         to the downstream NGL processing facilities 112 and the aqueous         phase (with Methanol or an alternative anti-freeze fluid like         MEG, if required and injected upstream) 114 is re-injected 120         into the gas stream downstream of the JT-Valve 106.     -   The expanded and chilled gas from the JT-Valve 106 is then         routed to the Gas-Gas Exchanger 104 for heat cross exchange to         chill the incoming feed gas stream. Prior to routing to the         Gas-Gas Exchanger, condensed water (with methanol or alternative         anti-freeze and/or hydrate inhibitor, if required) from the Cold         Separator with make-up of fresh water is injected 120 into the         gas stream from the JT-Valve. In addition, the heated and water         saturated gas downstream of the Gas-Gas Exchanger may be cooled         and the condensed water removed and recycled for injection         upstream of the Gas-Gas Exchanger. This will potentially avoid         the need for make-up Fresh Water.     -   At the Gas-Gas Exchanger 104, the chilled gas increases in         temperature (i.e. is superheated) by the incoming hot feed gas         stream and simultaneously evaporation of the injected aqueous         medium in the cold side of the exchanger occurs. To maximize the         cooling duty of the exchanger (and thus minimize the hot feed         gas stream outlet temperature), the injection rate of the         condensed and fresh water make-up is set to saturate the cold         side gas at its outlet conditions. An excess amount may be         injected beyond its saturation point to ensure that TDS content         of the aqueous phase does not exceed its saturation point to         avoid solid deposition at the Gas-Gas Exchanger 104.     -   From the Gas-Gas Exchanger 104, the heated gas stream is routed         to the downstream gas facilities.

Unlike conventional JT Valve systems, where the JT Valve is located upstream of the cold separator, according to this embodiment of the invention the JT Valve is located downstream of the Cold Separator. This configuration maximizes liquid drop-out from the associated gas stream for low operating pressures of the associated gas as the condensate removal is done at higher pressures for the reasons set out hereinbefore.

Note that if the operating temperatures are dropped to below the hydrate or ice formation temperature, hydrate (or anti-freeze) injection will be required. The advantage of this system is that the HCDPC unit is operated at low pressure, resulting in hydrate formation temperatures being significantly lower, thus mostly avoiding the need for hydrate inhibitor. If, however, operating temperatures are below 0° C., anti-freeze injection will be required.

Downstream of the JT Valve, with pressure letdown, the water content in the gas is lower than saturation. In addition, with the gas being further heated at the Gas/Gas Exchanger, the gas stream is further under-saturated. This is demonstrated in FIG. 4 which gives for the above example, saturated water content of the natural gas at various pressures and temperatures.

For the current example, Point B on the above plot corresponds to the water content of gas from the Cold Separator, upstream of the JT Valve (which is at saturated water content conditions). If no water is added to the gas stream downstream of the JT-Valve, the water content of the gas at the outlet of the Gas-Gas-Exchanger will remain as that at Point B. To maximize the chilling effect due to evaporation of water, water is required to be injected to fully water saturate the gas at the outlet of the Gas-Gas Exchanger. This corresponds to Point C in the above plot. Thus, the amount of fresh water needed to be injected corresponds to the differential water content of the gas between Point B and Point C. This is equivalent to a water injection rate of approximately 2750 kg/MMscf of gas. Point A of the above plot corresponds to the water content of the hot feed gas stream at inlet to the Gas-Gas Exchanger. An excess amount of water is dosed into the gas to prevent fouling at the Gas-Gas Exchanger. The amount of excess water dosed is such that at the outlet of the Gas-Gas Exchanger, the TDS in the water phase is below its saturation TDS content. This is to ensure that solids do not precipitate out of the water as it vaporized in the Gas-Gas Exchanger.

Thus, the sensible heat due to heating the gas from Point B to Point C plus the latent heat due to vaporization of the water phase as the fluid transverses the Gas-Gas Exchanger is exchanged with the hot feed gas stream to cool the latter. The latent heat due to vaporization of the water phase provides the additional chilling duty to maximize the chilling duty of the exchanger, thus, further cooling the hot feed gas stream.

Another feature of the system is to utilize condensed water, separated from condensed NGLs, in the Cold Separator as part or all of the water dosing requirements. This will eliminate or minimize the need for fresh water requirements from an external source. For the above example, the amount of condensed water collected in the Cold Separator is equivalent to water content of Point A (1150 kg/MMscf) minus water content of Point B (˜0 kg/MMscf) which corresponds to approximately 1150 kg/MMscf This is the amount of water that is re-injected into the gas stream downstream of the JT-Valve. Thus, the net amount of make-up fresh water required is 1600 kg/MMscf (2750 kg/MMscf minus 1150 kg/MMscf) to fully saturate the gas at cold side outlet of the Gas-Gas Exchanger. Note also that the fresh water may also be sourced from upstream or downstream of the process provided it has low impurities and TDS that will not contribute to fouling of the Gas-Gas Exchanger.

Another feature of this invention is that, whilst for conventional systems, the cold separator is installed downstream of the gas expansion device where the gas supply pressure is typically above its cricondentherm, for low pressure feed gas, the cold separator is upstream of the device as it is at the higher pressure where higher liquid drop-out occurs when gas feed is lower than its cricondentherm pressure, although temperatures are higher than that downstream of the gas expansion device. This point is demonstrated on the phase envelope of the gas in FIG. 5.

In the plot, Point A is the operating point of the feed gas stream, Point B is the operating point of the gas upstream of the expansion device and Point C is the operating point of the gas downstream of the expansion device. It is noted that if the gas/liquid separation is performed at Point B, i.e. downstream of the expansion device, as is done conventionally, Point B sits on the quality line 0.015. If however, the gas/liquid separation is undertaken upstream of the expansion device i.e. at Point C, in accordance with the invention, Point C sits on the quality line 0.025. This indicates that with gas/liquid separation being performed upstream of the expansion device when operating pressures are low (approximately less than the cricondentherm), the operating point moves deeper into the phase envelope, thus resulting in higher amounts of NGL recovery from the natural gas stream, although temperatures are higher upstream of the expansion device.

Downstream of the expansion device which is at a lower pressure, the water dew point of gas, in many cases, is expected to be lower than the operating temperature of the gas. An exception may be when a turbo-expander is used as the expansion device where, due to the relatively deep chilling inherent with these devices, the exiting gas temperature may be below its water dew point temperature. In either case, as the expanded gas is heated-up via cross heat exchange with incoming feed gas at the Gas-Gas Exchanger, the gas will be superheated.

Conventionally, the leaner gas after the expansion device (with condensed liquids already removed) has a smaller mass flow (and enthalpy) than the incoming rich feed gas stream. This results in limited heat transfer between the two streams at the Gas-Gas Exchanger. This makes the system in its conventional form very ineffective particularly when feed gas pressures are low.

To overcome the above issues, the strategy adopted, in accordance with the invention, is to inject an evaporative medium; in this case water, into the low pressure gas stream, downstream (or upstream) of the gas expansion device, to provide additional chilling duty to cool the water dew-pointed gas which in turn cools the incoming feed gas stream. To maximize the chilling duty of the Gas-Gas Exchanger, water is injected at a rate such that the gas exiting the Gas-Gas Exchanger is water saturated with a slight excess water to ensure that the Total Dissolved Solid (TDS) content in the water does not exceed its saturation point. This is to avoid precipitation of solids from the water at the Gas-Gas Exchanger.

It is noted that if hydrates or ice formation is envisaged under operating conditions, appropriate hydrate inhibitor, like methanol, MEG, etc. will be required.

With reference to FIGS. 6-7, an additional embodiment of this invention includes the injection of hydrocarbon liquid, namely crude from the upstream 1st stage separator, into the feed gas stream. The spiked crude functions as an absorbent of NGLs.

Crude is spiked into the associated gas stream to shift the vapor faction of the gas stream from single-phase region into two-phase region. Thus, the phase envelope of the stream to the HCDPC unit changes and maximizes condensate recovery on cooling to a specified temperature.

The advantage is that the dewpointing of the gas and the recovery of the C4+ components from the gas stream can be undertaken at relatively high temperatures (of approximately 12° C.) which will avoid operating within the hydrate formation and icing temperature range, thus avoiding the need for hydrate inhibitors. Other than that, crude spiked can act as absorbent for the absorption of some C4+ component from the gas stream thus maximizing oil recovery.

FIG. 8 illustrates another embodiment 202 of the invention comprising a Turbo-Expander 222 instead of a JT-Valve as the gas expansion device.

The system 202 is similar to the prior art illustrated in FIG. 2, but wherein the feed gas 210 is passed to a warm separator 224 downstream of the gas/gas heat exchanger 204 before being directed to expansion means in the form of turbo expander 222. Liquid is directed to a discharge scrubber 228 via a cooler 226, where lean gas is directed to a flare point 218 and NGLs are recovered at an outlet 212. Gas from the turbo expander is directed from the outlet 216 to a cold separator 208 which allows recovery of NGLs at the outlet 212 and directs gas through the heat exchanger 204 and back to the turbo expander 222.

As with the JT Valve system, whilst the Turbo-Expander is widely used for hydrocarbon dew point control, this system is not suitable for low pressure gas e.g. below 20 barg (2.1 MPa). As can be seen, minimum temperatures achievable with the conventional configuration, with feed gas pressure of 5 barg and temperature of 68.8° C., is approximately 26.4° C. and will not result in significant NGL (condensate) recovery as indicated in the above example where only 112 BPD of NGLs is condensed at the separators.

FIG. 9 illustrates an embodiment of the with a turbo expander wherein deep chilling of the natural gas stream enhances the recovery of NGLs.

The following describes the configuration of the system 302:

-   -   Feed gas 310 from the upstream production facility is routed to         a Gas-Gas Exchanger 304. A hydrate inhibitor or anti-freeze e.g.         methanol is injected into the feed gas stream to prevent         hydrates and/or icing of condensed water as the hot feed gas         stream is chilled at the Gas-Gas Exchanger by cold gas stream         from the Turbo-Expander 322. The injection rate is set such that         the following is met:         -   Hydrates or freezing of the aqueous phase will not occur             when feed gas stream is chilled at the Gas-Gas Exchanger.         -   Concentration of the inhibitor in the aqueous phase at the             separator/scrubber should be high enough for re-injection             into the gas stream downstream of the Turbo-Expander. If             required, additional inhibitor is injected at this location             to make-up for the short-fall in concentration.     -   The chilled feed gas stream is then routed to the Cold Separator         308 where 3 phase gas-oil-water separation is undertaken.     -   The separated gas is routed to the Turbo-Expander 322, the oil         to the downstream NGL processing facilities and the aqueous         phase (with Methanol or an alternative anti-freeze fluid like         MEG) is re-injected into the gas stream downstream of the         Turbo-Expander. A gas scrubber 328 may be installed downstream         of the Turbo-Expander if significant condensation of NGLs is         expected although for low pressure services, the amount, if any,         is not expected to be significant. Most of the NGLs are expected         to be removed 312 at the upstream Cold Separator for the same         reasons as detailed in the JT Valve embodiment. Lean gas is         flared 318.     -   The expanded and chilled gas from the Turbo-Expander is then         routed 316 to the Gas-Gas Exchanger for heat cross exchange to         chill the incoming feed gas stream. Prior to routing to the         Gas-Gas Exchanger, an aqueous solution of methanol (or         alternative anti-freeze and/or hydrate inhibitor) is injected         320, being sourced from the Cold Separator and the downstream         scrubber. Any shortfall in injection requirements will be with         make-up fresh water appropriately dosed with inhibitor.     -   At the Gas-Gas Exchanger 304, the chilled gas increases in         temperature (i.e. is superheated) by the incoming hot feed gas         stream and simultaneously evaporation of the injected aqueous         medium in the cold side of the exchanger occurs. To maximize the         cooling duty of the exchanger (and thus minimize the hot feed         gas stream outlet temperature), the injection rate of the         aqueous medium is set to saturate the cold side gas at its         outlet conditions. An excess amount may be injected beyond its         saturation point to ensure that TDS content of the aqueous phase         does not exceed its saturation point to avoid solid deposition         at the Gas-Gas Exchanger.     -   From the Gas-Gas Exchanger, the heated gas stream is routed to a         gas scrubber 330 to remove or recycle for re-injection excess         aqueous medium and then is routed to the gas compressor that is         coupled on a single shaft with the Turbo-Expander.     -   Downstream of the Gas Compressor, the gas is cooled in a cooler         326 and routed to a gas scrubber. Any condensed water with         inhibitor separated at the gas scrubber is re-injected to the         chilled gas stream upstream of the Gas-Gas Exchanger.     -   It is noted that the temperatures downstream of the         Turbo-Expander may be very low (below −50° C.) and may require         very high methanol concentrations of the injected aqueous medium         upstream of the Gas-Gas Exchanger to avoid freezing on contact         with the gas from the Turbo-Expander. To mitigate this, the         Gas-Gas Exchanger may be split to allow the gas to be warm at         the 1st section of the exchanger prior to injection of the         aqueous medium.

Unlike conventional Turbo-Expander systems, most of the condensed hydrocarbon liquids are collected in the separator upstream of Turbo-Expander. This configuration maximizes liquid drop-out from the associated gas stream for low operating pressures of the associated gas as the condensate removal is done at higher pressures.

Unlike the case with the JT Valve system, downstream of the Turbo-Expander, due to the deep chilling effect, temperatures are expected to drop to below the gas water dew-point unless the gas is dehydrated upstream of the Turbo-Expander. Notwithstanding this, the gas phase is already saturated with methanol and will prevent freezing of water drop-out. With the gas being further heated at the Gas/Gas Exchanger, the gas stream exiting the Gas-Gas Exchanger will conventionally be under-saturated.

In the similar fashion to that of the JT-Valve embodiment, to maximize the chilling effect due to evaporation of water, water with an appropriate concentration of hydrate or ice inhibitor is injected fully water saturate the gas at the outlet of the Gas-Gas Exchanger. An excess amount of water is dosed into the gas to prevent fouling at the Gas-Gas Exchanger. The amount of excess water dosed is such that at the outlet of the Gas-Gas Exchanger, the TDS in the water phase is below its saturation TDS content. This is to ensure that solids do not precipitate out of the water as it vaporized in the Gas-Gas Exchanger.

Another feature of the system is to utilize condensed water, separated from condensed NGLs, in the Cold Separator and downstream gas scrubber as part or all of the water dosing requirements. This will eliminate or minimize the need for fresh water requirements from an external source. Note also that the fresh water may also be sourced from upstream or downstream of the process provided it has low impurities and TDS that will not contribute to fouling of the Gas-Gas Exchanger.

It will be appreciated by persons skilled in the art that the present invention may also include further additional modifications made to the system which does not affect the overall functioning of the system. 

In the claims:
 1. A system (102; 302) for recovering natural gas liquid from a gas source (110; 310), comprising: a gas/gas heat exchanger (104; 304) including a first inlet and first outlet, fluid from the gas source flowing from the first inlet to the first outlet; at least one separator (108; 308) for receiving the fluid from the first outlet of the gas/gas heat exchanger (104; 304) and separating liquid from the gas, the gas being directed via a connecting pipe (116; 316) to the gas/gas heat exchanger (104; 304) where it flows therethrough from a second inlet to a second outlet for cooling the fluid flowing between the first inlet and first outlet; characterised in that the connecting pipe (116; 316) includes expansion means (106; 322) for cooling the gas therein and liquid injection means (120; 320) for saturating the gas with liquid.
 2. The system according to claim 1 wherein the expansion means is a Joule-Thomson valve (106).
 3. The system according to claim 1 wherein the expansion means is a Vortex-Tube Device or Supersonic Tube technology.
 4. The system according to claim 1 wherein the expansion means is a turbo expander (322).
 5. The system according to claim 1 wherein the liquid injection means is downstream of the expansion means.
 6. The system according to claim 1 wherein liquid is injected downstream of the expansion means at a rate to enable the gas at the second outlet to be saturated.
 7. The system according to claim 1 wherein liquid is injected in excess of the saturation amount to avoid solid deposition at the gas/gas heat exchanger.
 8. The system according to claim 1 wherein the liquid used to saturate the gas is derived from the separator and/or other downstream sources.
 9. The system according to claim 1 wherein the liquid injection means is a sprayer for spraying the liquid into the gas as a mist.
 10. The system according to claim 1 wherein the liquid used to saturate the gas is water.
 11. The system according to claim 1 wherein the liquid used to saturate the gas is mixed with a hydrate or ice inhibitor.
 12. The system according to claim 11 wherein the hydrate or ice inhibitor is methanol or Mono Ethylene Glycol.
 13. The system according to claim 1 wherein the gas source pressure of less than 2.1 MPa. 